This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for numerous years. To produce these hydrocarbons, one or more wells of a field are typically drilled into a subsurface location, which is generally referred to as a subterranean formation or basin. The process of producing hydrocarbons from the subsurface location typically involves the use of various equipment and facilities to transport the hydrocarbons from the subsurface formation to delivery locations. As such, the production and transportation of these hydrocarbons may involve equipment that includes “oil country tubular goods” (OCTG) such as tubulars, pipelines and various apparatus that are made of steels and other materials.
The fluids being transported often contain other fluids in addition to the hydrocarbons, such as the produced formation fluids, which may be corrosive and can corrode and damage the production and transportation equipment. To mitigate the consequences of corrosion, current approaches generally involve either using equipment made of expensive, highly alloyed metals known as “corrosion resistant alloys” (CRAs) or using inexpensive carbon steels coupled with additional corrosion control measures including inspections, coatings, inhibition, cathodic protection, periodic repair/replacement. A low cost alloy having enhanced corrosion resistance can thus provide cost saving benefits through either replacing the expensive CRAs to reduce the capital cost, or through replacing the carbon steels and eliminate the operating costs associated with the additional corrosion control measures.
It is further noted that a low cost alloy with enhanced corrosion resistance as described above can provide further benefits if it also has suitable corrosion resistance in the oxygen containing aqueous fluids typically encountered in water injection wells, and as such will have additional applications as OCTG tubulars in conversion wells and dual purpose wells. Conversion wells are those that are originally used as hydrocarbon producing wells, which are later converted into water injection wells. These wells typically use tubulars made of alloys having corrosion resistance to production fluids during their hydrocarbon producing phase, but later change the tubulars at additional costs to ones made of alloys having corrosion resistance in oxygen containing fluids for water injection operations. The dual purpose wells are those that simultaneously produce hydrocarbons, e.g. through the production tubulars, and inject water into subterranean formations, e.g. through the annulus between the production tubular and casing. These wells typically use tubulars made of expensive, highly alloyed CRAs having corrosion resistance in both production and oxygen containing fluids. Thus, the low cost alloys having enhanced corrosion resistance in both production and oxygen containing fluids can provide significant cost savings when used as OCTG tubulars in the case of conversion wells, which do not require changing the tubulars when converted into water injection wells, and in the case of dual purpose wells to replace the expensive CRA tubulars.
Typical CRA compositions derive their corrosion resistance from large alloying additions, such as chromium (Cr), exceeding about 12-13 weight-percent (wt %). This amount of chromium, e.g. 13 wt % Cr, is the minimum amount needed to form a complete surface coverage of nanometer thick passive film for the corrosion protection, see ASM Handbook, vol. 13A: Corrosion 2003 Ed. p. 697; and Corrosion of Stainless Steels, A. J. Sedriks, p. 1 and FIG. 1.1 (Wiley, 1996). In fact, compositions having iron (Fe)-13 wt % Cr is the basic composition of the lowest cost CRA, which is often referred to as 13Cr steels. With iron (Fe) being an inexpensive metal, any additional alloying generally increases the cost of the alloy. Accordingly, the higher classes of CRAs contain not only more chromium, but also more of other more expensive alloying elements, such as molybdenum (Mo), to further improve their passive film performance, and resulting in even higher material costs. In the oil and gas industry, concerns over aqueous corrosion often dictates the materials selected for application in the exploration, production, refining and chemical equipment and installations. See ASM Handbook, vol. 13A: Corrosion 2003 Ed. p. 697. For instance, in typical oil and gas exploration and production operations, carbon steels constitute the bulk of the structural alloys used due to their low cost, The more costly CRAs, on the other hand, are used only in production fields that have severe corrosion environments, and as a result they constitute only a small fraction of the total tonnage used. See ASM Handbook, vol. 13: Corrosion 1987 Ed. p. 1235.
To reduce costs, some research groups and steel companies have recently worked on developing low alloy carbon steels that have improved corrosion resistance, which typically focuses on developing Cr-containing steels in which the material cost is reduced by lowering the nominal chromium content to 3 wt % or less. The fraction of chromium available for corrosion resistance in the solid solution is then maximized by the addition of strong carbide forming elements as vanadium (V), titanium (Ti) and niobium (Nb). These elements, by tying up carbon in the matrix as carbide precipitates, effectively increase the amount of free chromium remaining in the matrix for corrosion resistance. For instance, steels containing 3 wt % Cr and 1 wt % Cr have been lab tested in synthetic sea and production waters, while various 3 wt % Cr steels have been lab tested in simulated sweet fluids as well as NACE (National Association of Corrosion Engineers) solutions. Further, carbon steels having Cr content ranging between 1-5 wt % have been tested with a variety of simulated production fluids. Finally, surface characteristics of 4 wt % Cr steels exposed to brines extracted from oil field fluids have also been investigated.
From these tests and reports, the 3 to 5 wt % Cr steels display superior corrosion resistance to carbon steels in sweet (CO2) and mildly sour (H2S) production environments. However, when exposed to oxygen levels above 20 parts per billion (ppb), localized corrosion in the form of pitting was identified on all samples. See Michael John Schofield et al., “Corrosion Behavior of Carbon Steel, Low Alloy Steel and CRA's in Partially Deaerated Sea Water and Commingled Produced Water,” Corrosion, 2004 Paper No. 04139. Steels containing lower Cr levels, viz. 1 wt % Cr, display lower corrosion rates in oxygenated environments with the absence of pitting. See Chen Changfeng et al., “The Ion Passing Selectivity of CO2 Corrosion Scale on N80 Tube Steel,” Corrosion, 2003, Paper No. 03342. Indeed, 1 wt % Cr steels are commercially available for water injection applications, however, these steels do not offer adequate protection under lower pH (5-6) sweet (CO2) environments at temperatures of 60° C. See Michael John Schofield et al. and C. Andrade et al., Proceedings of OMAE '01 20th International Conference on Offshore Mechanics and Arctic Engineering, Jun. 3-8, 2001, Rio de Janeiro, Brazil. Consequently, the low Cr steels, containing 0-5 wt % Cr, are inadequate for applications in the conversion and dual purpose wells, which are described above.
Accordingly, the need exists for inexpensive, low alloy steels that combine resistance to uniform or general corrosion with resistance to pitting or localized corrosion in environments of interest in oil and gas production.
Further, additional information may be found in Supplement to Materials Performance, July 2002, pp. 4-8: FIG. 5; ASM Handbook, vol. 13A: Corrosion, 2003 ed. p. 697; Corrosion of Stainless Steels, A. J. Sedriks, p. 1 and FIG. 1.1 (Wiley, 1996); B. Kermani, et al., “Materials Optimization in Hydrocarbon Production”, Corrosion/2005 Paper No. 05111; M. B. Kermani, et al., “Development of Low Carbon Cr—Mo Steels with Exceptional Corrosion Resistance for Oilfield Applications,” Corrosion/2001, paper No. 01065; H. Takabe et al., “Corrosion Resistance of Low Cr Bearing Steel in Sweet and Sour Environments,” Corrosion/2002, Paper No. 02041; K. Nose, et al., “Corrosion Properties of 3% Cr Steels in Oil and Gas Environments,” Corrosion/2001, Paper No. 01082; T. Muraki, et al., “Development of 3% Chromium Linepipe Steel,” Corrosion/2003, Paper No. 03117; Chen Changfeng et al., “The Ion Passing Selectivity of CO2 Corrosion Scale on N80 Tube Steel,” Corrosion/2003, Paper No. 03342; M. J. Schofield, et al., “Corrosion Behavior of Carbon Steel, Low Alloy Steel and CRA's in Partially Deaerated Sea Water and Commingled Produced Water,” Corrosion/2004 Paper No. 04139; C. Andrade, et al., “Comparison of the Corrosion Behavior of Carbon Steel and 1% Chromium Steels for Seawater Injection Tubings”, Proceedings of OMAE '01 20th International Conference on Offshore Mechanics and Arctic Engineering Jun. 3-8, 2001, Rio de Janeiro, Brazil; CALPHAD—Calculation of Phase Diagrams, Eds. N. Saunders, A. P. Miodownik (Pergamon, 1998); and “Thermo-Calc ver M, Users' Guide,” by Thermo-Calc Software, Thermo-Calc Software, Inc, McMurray, Pa. 15317, USA (2000).